Quarterly Report (10-q)

Large Accelerated Filer

Accelerated Filer

Non-Accelerated Filer

Smaller Reporting Company

Emerging growth company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM

10-Q

☒	REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended September 30, 2022

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period From

Commission File Number

0-7406

PrimeEnergy Resources Corporation

(Exact name of registrant as specified in its charter)


Delaware		84-0637348
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer Identification No.)

9821 Katy Freeway, Houston, Texas 77024

(Address of principal executive offices)

(713)

735-0000

(Registrant’s telephone number, including area code)

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock, $0.10 par value	PNRG	NASDAQ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings required for the past 90 days. Yes

☒ No ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation

S-T

(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes

☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a

non-accelerated

filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule

12b-2

of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule

12b-2

of the Exchange Act). Yes ☐ No ☒

The number of shares outstanding of each class of the Registrant’s Common Stock as of November 18, 2022 was: Common Stock, $0.10 par value 1,920,500 shares.

PrimeEnergy Resources Corporation

Index to Form 10-Q

September 30, 2022


	Page
Part I—Financial Information
Item 1. Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2022 and December 31, 2021		3
Condensed Consolidated Statements of Operations – For the three and nine months ended September 30, 2022 and 2021		4
Condensed Consolidated Statements of Equity – For the nine months ended September 30, 2022 and 2021		5
Condensed Consolidated Statements of Cash Flows – For the nine months ended September 30, 2022 and 2021		6
Notes to Condensed Consolidated Financial Statements – September 30, 2022		7-12
Item 2. Management’s Discussion and Analysis of Financial Conditions and Results of Operation		13
Item 3. Quantitative and Qualitative Disclosures About Market Risk		22
Item 4. Controls and Procedures		22

Part II—Other Information

Item 1. Legal Proceedings		23

Item 1A. Risk Factors		23

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		23

Item 3. Defaults Upon Senior Securities		23

Item 4. Reserved		23

Item 5. Other Information		23

Item 6. Exhibits		24

Signatures		25

Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments. 0000056868 2021-12-31 0000056868 2022-09-30 0000056868 2021-01-01 2021-09-30 0000056868 2022-01-01 2022-09-30 0000056868 2021-09-30 0000056868 2022-07-01 2022-09-30 0000056868 2021-07-01 2021-09-30 0000056868 1989-05-31 0000056868 2022-11-18 0000056868 2020-12-31 0000056868 us-gaap:CommodityContractMember us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2022-09-30 0000056868 us-gaap:FairValueMeasurementsRecurringMember us-gaap:CommodityContractMember 2022-09-30 0000056868 us-gaap:FairValueMeasurementsRecurringMember us-gaap:FairValueInputsLevel3Member 2022-09-30 0000056868 us-gaap:FairValueMeasurementsRecurringMember 2022-09-30 0000056868 pnrg:NonstatutoryStockOptionsMember 2022-09-30 0000056868 srt:MinimumMember 2022-09-30 0000056868 srt:MaximumMember 2022-09-30 0000056868 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xbrli:shares pnrg:Officers

PART I—FINANCIAL INFORMATION

Item 1.

FINANCIAL STATEMENTS

PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

ALANCE

HEETS

– Unaudited

(Thousands of dollars)


	September 30, 2022			December 31, 2021
ASSETS
Current Assets
Cash and cash equivalents	$	24,059		$	10,347
Accounts receivable, net		16,943			14,208
Prepaid obligations		783			733
Other current assets		348			40

Total Current Assets		42,133			25,328
Property and Equipment
Oil and gas properties at cost		545,345			539,484
Less: Accumulated depletion and depreciation		(380,287	)		(359,742	)

		165,058			179,742

Field and office equipment at cost		28,013			27,080
Less: Accumulated depreciation		(23,041	)		(22,159	)

		4,972			4,921

Total Property and Equipment, Net		170,030			184,663
Derivative asset long-term and other assets		736			923

Total Assets	$	212,899		$	210,914

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	6,168		$	7,282
Accrued liabilities		10,526			7,821
Due to related parties		113			52
Current portion of asset retirement and other long-term obligations		1,438			1,630
Derivative liability short-term		3,975			4,935

Total Current Liabilities		22,220			21,720
Long-Term Bank Debt		—			36,000
Asset Retirement Obligations		12,460			13,222
Derivative Liability Long-Term		—			650
Deferred Income Taxes		47,518			38,743
Other Long-Term Obligations		1,323			1,488

Total Liabilities		83,521			111,823
Commitments and Contingencies
Equity
Common stock, $.10 par value; 2022 and 2021: Authorized: 2,810,000 shares, outstanding 2022: 1,930,700 shares; outstanding 2021: 1,992,077 shares.		281			281
Additional paid-in capital		7,555			7,555
Retained earnings		164,181			128,902
Treasury stock, at cost; 2022: 879,300 shares; 2021: 817,923 shares		(42,639	)		(37,647	)

Total Equity		129,378			99,091

Total Liabilities and Equity	$	212,899		$	210,914

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

TATEMENTS

PERATIONS

– Unaudited

Three and nine months ended September 30, 2022 and 2021

(Thousands of dollars, except per share amounts)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2022			2021			2022			2021
Revenues
Oil sales	$	23,403		$	10,442		$	75,546		$	30,376
Natural gas sales		6,359			3,998			14,762			7,948
Natural gas liquids sales		4,204			3,632			12,477			7,781
Realized (loss) on derivative instruments, net		(4,285	)		(1,983	)		(13,992	)		(2,896	)
Field service income		3,846			2,415			10,822			6,215
Unrealized gain (loss) on derivative instruments, net		6,124			(1,194	)		1,918			(7,162	)
Other income		—			1			29			30

Total Revenues		39,651			17,311			101,562			42,292
Costs and Expenses
Lease operating expense		8,679			6,396			26,613			15,298
Field service expense		3,005			2,925			9,545			6,180
Depreciation, depletion, amortization and accretion on discounted liabilities		7,732			6,883			21,931			19,990
General and administrative expense		2,453			1,984			11,543			6,183

Total Costs and Expenses		21,869			18,188			69,632			47,651
Gain on Sale and Exchange of Assets		494			5			15,330			111

Income (Loss) from Operations		18,276			(872	)		47,260			(5,248	)
Other Income (Expense)
Interest Income		8			—			8			—
Interest Expense		(253	)		(462	)		(752	)		(1,469	)

Income (Loss) Before Income Taxes		18,031			(1,334	)		46,516			(6,717	)
Income Taxes Expense (Benefit)		4,877			(186	)		11,237			(1,700	)

Net Income (Loss)		13,154			(1,148	)		35,279			(5,017	)
Less: Net Income Attributable to Non-Controlling Interests		—			15			—			4

Net Income (Loss) Attributable to PrimeEnergy	$	13,154		$	(1,163	)	$	35,279		$	(5,021	)

Basic Income (Loss) Per Common Share	$	6.79		$	(0.58	)	$	17.95		$	(2.52	)

Diluted Income (Loss) Per Common Share	$	4.88		$	(0.58	)	$	12.96		$	(2.52	)

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

TATEMENTS

QUITY

– Unaudited

Nine months Ended September 30, 2022 and 2021

(Thousands of dollars)


	Common Stock
	Shares			Amount		Additional Paid-In Capital		Retained Earnings			Treasury Stock			Total Stockholders’ Equity – PrimeEnergy			Non- Controlling Interest			Total Equity
Balance at December 31, 2021		1,992,077		$	281	$	7,555	$	128,902		$	(37,647	)	$	99,091		$	—		$	99,091
Purchase 61,377 shares of Common stock		(61,377	)		—		—		—			(4,992	)		(4,992	)		—			(4,992	)
Net Income		—			—		—		35,279			—			35,279			—			35,279
Balance at September 30, 2022		1,930,700		$	281	$	7,555	$	164,181		$	(42,639	)	$	129,378		$	—		$	129,378

Balance at December 31, 2020		1,994,177		$	281	$	7,541	$	126,804		$	(37,502	)	$	97,124		$	874		$	97,998
Net (Loss) Income									(5,021	)					(5,021	)		4			(5,017	)
Purchase of non- controlling interest		—			—		19		—			—			19			(25	)		(6	)

Balance at September 30, 2021		1,994,177		$	281	$	7,560	$	121,783		$	(37,502	)	$	92,122		$	853		$	92,975

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

ONDENSED

ONSOLIDATED

TATEMENTS

ASH

LOWS

–

Unaudited

Nine months ended September 30, 2022 and 2021

(Thousands of dollars)


	2022			2021
Cash Flows from Operating Activities:
Net Income (Loss)	$	35,279		$	(5,017	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, amortization and accretion on discounted liabilities		21,931			19,990
Gain on sale of properties		(15,330	)		(111	)
Unrealized (gain) loss on derivative instruments, net		(1,918	)		7,162
Provision for deferred income taxes		8,775			(1,700	)
Changes in operating assets and liabilities:
Accounts receivable		(2,735	)		(7,120	)
Due to related parties		61			(4	)
Other assets		(308	)		(655	)
Accounts payable		(1,114	)		6,170
Accrued liabilities		2,705			109

Net Cash Provided by Operating Activities		47,346			18,824

Cash Flows from Investing Activities:
Capital expenditures		(7,972	)		(11,301	)
Proceeds from sale of properties and equipment		15,330			111

Net Cash Provided by (Used in) Investing Activities		7,358			(11,190	)

Cash Flows from Financing Activities:
Purchase of stock for treasury		(4,992	)		—
Purchase of non-controlling interests		—			(6	)
Proceeds from long-term bank debt and other long-term obligations		—			3,000
Repayment of long-term bank debt and other long-term obligations		(36,000	)		(8,000	)

Net Cash (Used in) Financing Activities		(40,992	)		(5,006	)

Net Increase in Cash and Cash Equivalents		13,712			2,628
Cash and Cash Equivalents at the Beginning of the Period		10,347			996

Cash and Cash Equivalents at the End of the Period	$	24,059		$	3,624

Supplemental Disclosures:
Income taxes paid	$	61		$	—
Interest paid	$	714		$	1,384

The accompanying Notes are an integral part of these Condensed Consolidated Financial Statements

Table of Contents

PRIMEENERGY RESOURCES CORPORATION

OTES

ONDENSED

ONSOLIDATED

INANCIAL

TATEMENTS

September 30, 2022

(1) Basis of Presentation:

The accompanying condensed consolidated financial statements of PrimeEnergy Resources Corporation (“PrimeEnergy” or the “Company”) have not been audited by independent public accountants. Pursuant to applicable Securities and Exchange Commission (“SEC”) rules and regulations, the accompanying interim financial statements do not include all disclosures presented in annual financial statements and the reader should refer to the Company’s Form

10-K

for the year ended December 31, 2021. In the opinion of management, the accompanying interim condensed consolidated financial statements contain all material adjustments, consisting only of normal recurring adjustments, necessary for a fair presentation of the Company’s condensed consolidated balance sheets as of September 30, 2022 and December 31, 2021, and the condensed consolidated statements of operations, equity and cash flows for the nine months ended September 30, 2022 and 2021.

As of September 30, 2022, PrimeEnergy’s significant accounting policies are consistent with those discussed in Note 1—Description of Operations and Significant Accounting Policies of its consolidated financial statements contained in PrimeEnergy’s Annual Report on Form

10-K

for the fiscal year ended December 31, 2021. Certain amounts presented in prior period financial statements have been reclassified for consistency with current period presentation. The results for interim periods are not necessarily indicative of annual results. For purposes of disclosure in the condensed consolidated financial statements, subsequent events have been evaluated through the date the statements were issued and included in Footnote 2.

(2) Acquisitions and Dispositions:

the first quarter of 2022, the Company sold

1,809

net leasehold acres in Reagan and Midland Counties, Texas through two separate transactions receiving gross proceeds of $

14.0

million.

the second quarter of 2022, the Company sold

241

net acres in Canadian County, Oklahoma for $

845,000

the third quarter of 2022, the Company sold an additional

113

net acres in Canadian County, Oklahoma for $

423,700

November 14, 2022, the Company completed an acreage exchange of approximately 725 net acres in the Midland Basin creating a block of

1,200

contiguous acres. The Company entered into an agreement, including this acreage, to create a

2,560

-acre

AMI for the joint development of horizontal wells. As part of the agreement, the Company sold a portion of its interest in this acreage to the joint development partner for proceeds of $

16.1

million.

(3) Additional Balance Sheet Information:

Certain balance sheet amounts are comprised of the following:


(Thousands of dollars)	September 30, 2022			December 31, 2021
Accounts Receivable:
Joint interest billing	$	2,338		$	1,902
Trade receivables		1,780			1,429
Oil and gas sales		13,095			11,154
Other		101			94

		17,314			14,579
Less: Allowance for doubtful accounts		(371	)		(371	)

Total	$	16,943		$	14,208

Accounts Payable:
Trade	$	1,428		$	2,390
Royalty and other owners		3,605			2,802
Partner advances		1,062			1,209
Other		73			881

Total	$	6,168		$	7,282

Table of Contents


(Thousands of dollars)	September 30, 2022		December 31, 2021
Accrued Liabilities:
Compensation and related expenses	$	4,211	$	3,919
Property costs		3,011		2,901
Taxes		3,213		893
Other		91		108

Total	$	10,526	$	7,821

(4) Long-Term Debt:

Bank Debt:

On February 15, 2017, the Company and its lenders entered into a Third Amended and Restated Credit Agreement (the “2017 Credit Agreement”) with a maturity date of February 15, 2021. Under the 2017 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2017 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, commodity hedge agreements, and loans and investments in its consolidated subsidiaries and limited partnerships.

On December 20, 2021 the company entered into a Seventh Amendment to the 2017 Credit Agreement and Citibank N.A was appointed as successor administrative agent replacing PNC Bank. Under this amendment the Company’s borrowing base is $50 million. Borrowings under the 2017 Credit Agreement will bear interest at alternate base rate (ABR) plus an applicable margin ranging from 2.00% to 3.00% or at the Company’s option, at a rate equal to the secured overnight financing rate (SOFR rate) as administered by the SOFR Administrator, in this case the Federal Reserve Bank of New York, plus an applicable margin ranging from 3.00% to 4.00%. The 2017 Credit Agreement matures February 11, 2023. The current borrowing base review and maturity extension was completed on July 5, 2022. The Company’s borrowings under this credit facility approximates fair value because the interest rates are variable and reflective of market rates.

On July 5, 2022 , the Company and its lenders entered into a Fourth Amended and Restated Credit Agreement (the “2022 Credit Agreement”) with a maturity date of June 1, 2026. Under the 2022 Credit Agreement, the Company has a revolving line of credit and letter of credit facility of up to $300 million subject to a borrowing base that is determined semi-annually by the lenders based upon the Company’s financial statements and the estimated value of the Company’s oil and gas properties, in accordance with the Lenders’ customary practices for oil and gas loans. The initial borrowing base of the agreement is $75 million. The credit facility is secured by substantially all of the Company’s oil and gas properties. The 2022 Credit Agreement includes terms and covenants that require the Company to maintain a minimum current ratio and total indebtedness to EBITDAX (earnings before depreciation, depletion, amortization, taxes, interest expense and exploration costs) ratio, as defined, and restrictions are placed on the payment of dividends, the amount of treasury stock the Company may purchase, and commodity hedge agreements.

As of September 30, 2022 the Company had

no borrowings outstanding under its current revolving credit facility.

(5) Other Long-Term Obligations and Commitments:

Operating Leases:

The Company leases office facilities under operating leases and recognizes lease expense on a straight-line basis over the lease term. Leases assets and liabilities are initially recorded at commencement date based on the present value of lease payments over the lease term. A new finance lease for office equipment is included in property and equipment, other current liabilities and other long-term liabilities this quarter. As most of the Company’s lease contracts do not provide an implicit discount rate, the Company uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. The weighted average discount rate used was 5.5%. Certain leases may contain variable costs above the minimum required payments and are not included in the

right-of-use

assets or liabilities. Leases may include renewal, purchase or termination options that can extend or shorten the term of the lease. The exercise of those options is at the Company’s sole discretion and is evaluated at inception and throughout the contract to determine if a modification of the lease term is required. Leases with an initial term of 12 months or less are not recorded on the balance sheet.

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Operating

lease costs for the nine months ended September 30, 2022 were $

468

thousand. Cash payments included in the operating lease costs for the nine months ended September 30, 2022 were $

499

thousand. The remaining operating lease terms range between

months.

The Company amended certain leases for office space in Texas providing for remaining payments of $174,000 in 2022, $251,000 in 2023, $107,000 in 2024 and $27,000 in 2025.

Office

space rent expense for the nine months ended September 30, 2022 and 2021 was $563,000 and $441,000, respectively.

The payment schedule for the Company’s operating lease obligations as of September 30, 2022 is as

follows:


(Thousands of dollars)	Operating Leases
2022		174
2023		251
2024		107
2025		27

Total undiscounted lease payments	$	559
Less: Amount associated with discounting		(54	)

Net operating lease liabilities	$	505

Asset Retirement Obligation:

A reconciliation of the liability for plugging and abandonment costs for the nine months ended September 30, 2022 is as follows:


(Thousands of dollars)	September 30, 2022
Asset retirement obligation at December 31, 2021	$	14,295
Liabilities incurred		11
Liabilities settled		(1,276	)
Accretion expense		503

Asset retirement obligation at September 30, 2022	$	13,533

(6) Contingent Liabilities:

The Company is subject to environmental laws and regulations. Management believes that future expenses, before recoveries from third parties, if any, will not have a material effect on the Company’s financial condition. This opinion is based on expenses incurred to date for remediation and compliance with laws and regulations, which have not been material to the Company’s results of operations.

From time to time, the Company is party to certain legal actions arising in the ordinary course of business. While the outcome of these events cannot be predicted with certainty, management does not expect these matters to have a materially adverse effect on the financial position or results of operations of the Company.

(7) Stock Options and Other Compensation:

In May 1989,

non-statutory

stock options were granted by the Company to four key executive officers for the purchase of shares of common stock. At September 30, 2022 and 2021, remaining options held by two key executive officers on 767,500 shares were outstanding and exercisable at prices ranging from $1.00 to $1.25. According to their terms, the options have no expiration date.

(8) Related Party Transactions:

Payables owed to related parties primarily represent receipts collected by the Company as agent for the joint venture partners, which may include members of the Company’s Board of Directors, for oil and gas sales net of expenses.

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(9) Financial Instruments

Fair Value Measurements:

Authoritative

guidance on fair value measurements defines fair value, establishes a framework for measuring fair value and stipulates the related disclosure requirements. The Company follows a three-level hierarchy, prioritizing and defining the types of inputs used to measure fair value. The fair values of the Company’s interest rate swaps, natural gas and crude oil price collars and swaps are designated as Level 3.

The following fair value hierarchy table presents information about the Company’s assets and liabilities measured at fair value on a recurring basis at September 30, 2022 and December 31, 2021:


September 30, 2022	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at September 30, 2022
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	308		$	308

Total assets	$	—	$	—	$	308		$	308

Liabilities
Commodity derivative contracts	$	—	$	—	$	(3,975	)	$	(3,975	)

Total liabilities	$	—	$	—	$	(3,975	)	$	(3,975	)


December 31, 2021	Quoted Prices in Active Markets For Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)			Balance at December 31, 2021
(Thousands of dollars)
Assets
Commodity derivative contracts	$	—	$	—	$	—		$	—

Total assets	$	—	$	—	$	—		$	—

Liabilities

Total liabilities	$	—	$	—	$	(5,585	)	$	(5,585	)

The derivative contracts were measured based on quotes from the Company’s counterparties. Such quotes have been derived using valuation models that consider various inputs including current market and contractual prices for the underlying instruments, quoted forward prices for natural gas and crude oil, volatility factors and interest rates, such as a LIBOR curve for a similar length of time as the derivative contract term as applicable. These estimates are verified using comparable NYMEX futures contracts or are compared to multiple quotes obtained from counterparties for reasonableness.

The significant unobservable inputs for Level 3 derivative contracts include basis differentials and volatility factors. An increase (decrease) in these unobservable inputs would result in an increase (decrease) in fair value, respectively. The Company does not have access to the specific assumptions used in its counterparties’ valuation models. Consequently, additional disclosures regarding significant Level 3 unobservable inputs were not provided.

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the nine months ended September 30, 2022.


(Thousands of dollars)
Net Liabilities – December 31, 2021	$	(5,585	)
Total realized and unrealized (gains) losses:
Included in earnings (a)		(12,074	)
Purchases, sales, issuances and settlements		13,992

Net Liabilities - September 30, 2022	$	(3,667	)

(a)	Derivative instruments are reported in revenues as realized gain/loss and on a separately reported line item captioned unrealized gain/loss on derivative instruments.

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Derivative Instruments:

The Company is exposed to commodity price and interest rate risk, and management considers periodically the Company’s exposure to cash flow variability resulting from the commodity price changes and interest rate fluctuations. Futures, swaps and options are used to manage the Company’s exposure to commodity price risk inherent in the Company’s oil and gas production operations. The Company does not apply hedge accounting to any of its commodity-based derivatives. Both realized and unrealized gains and losses associated with commodity derivative instruments are recognized in earnings.

The following table sets forth the effect of derivative instruments on the consolidated balance sheets at September 30, 2022 and December 31, 2021:


		Fair Value
(Thousands of dollars)	Balance Sheet Location	September 30, 2022			December 31, 2021
Asset Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative asset short-term	$	308		$	—

Total		$	308		$	—

Liability Derivatives:
Derivatives not designated as cash-flow hedging instruments:
Crude oil commodity contracts	Derivative liability short-term	$	(2,072	)	$	(3,992	)
Natural gas commodity contracts	Derivative liability short-term		(1,903	)		(943	)
Crude oil commodity contracts	Derivative liability long-term		—			(490	)
Natural gas commodity contracts	Derivative liability long-term		—			(160	)

Total derivative instruments		$	(3,975	)	$	(5,585	)

Total derivative instruments		$	(3,667	)	$	(5,585	)

The following table sets forth the effect of derivative instruments on the consolidated statements of operations for the nine months ended September 30, 2022 and 2021:


		Amount of gain/loss recognized in income
(Thousands of dollars)	Location of gain/loss recognized in income	2022			2021
Derivatives not designated as cash-flow hedge instruments:
Natural gas commodity contracts	Unrealized (loss) on derivative instruments, net	$	(800	)	$	(2,418	)
Crude oil commodity contracts	Unrealized gain (loss) on derivative instruments, net		2,718			(4,744	)
Natural gas commodity contracts	Realized (loss) on derivative instruments, net		(3,603	)		(1,009	)
Crude oil commodity contracts	Realized (loss) on derivative instruments, net		(10,389	)		(1,887	)

		$	(12,074	)	$	(10,058	)

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(10) Earnings Per Share:

Basic earnings per share are computed by dividing earnings available to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share reflect per share amounts that would have resulted if dilutive potential common stock had been converted to common stock in gain periods. The following reconciles amounts reported in the financial statements:


	Nine Months Ended September 30,
	2022						2021
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	35,279		1,965,334	$	17.95	$	(5,021	)		1,994,177	$	(2.52	)
Effect of dilutive securities:
Options (a)		—		757,218		—

Diluted	$	35,279		2,722,522	$	12.96	$	(5,021	)		1,994,177	$	(2.52	)


	Three Months Ended September 30,
	2022						2021
	Net Income (In 000’s)		Weighted Average Number of Shares Outstanding		Per Share Amount		Net Loss (In 000’s)			Weighted Average Number of Shares Outstanding		Per Share Amount
Basic	$	13,154		1,937,091	$	6.79	$	(1,163	)		1,994,177	$	(0.58	)
Effect of dilutive securities:
Options (a)		—		757,815		—		—			—		—

Diluted	$	13,154		2,694,906	$	4.88	$	(1,163	)		1,994,177	$	(0.58	)

(a)	The effect of the 767,500 outstanding stock options is antidilutive for the nine and three months ended September 30, 2021 due to net loss for these periods.

Item 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion is intended to assist you in understanding our results of operations and our present financial condition. Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.

OVERVIEW

We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas. We presently own producing and non-producing properties located primarily in Texas, and Oklahoma. We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia. We are currently not receiving revenue from this asset, as development has not begun. In addition, we own well-servicing equipment and, through a wholly owned offshore company, a 60-mile-long pipeline offshore on the shallow shelf of Texas not currently in use. We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama. There is currently no debt on the shopping center and it has approximately $500,000 of working capital on its balance sheet. All of our oil and gas properties and interests are located in the United States. Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as, newer properties with development and exploration potential. We believe our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities. Our primary sources of liquidity are cash generated from our operations, our credit facility and existing cash on our balance sheet.

In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties. We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition and for exploration and development operations in areas in which we own interests. To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities in the oil and gas business. Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value through consistent growth and development of our oil and gas reserve base on a cost-effective basis.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities, and the operational performance of our producing properties. We use derivative instruments to manage our commodity price risk. This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements. Since our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices. Our existing derivative instruments expire in March of 2023 and at this time we do not intend to enter into future derivative contracts unless required for our bank line of credit.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms. Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. In addition, our realized prices are further impacted by our derivative and hedging activities when used to manage commodity price risk. As mentioned above, our existing contracts are set to expire in March of 2023 and we currently do not intend to use future derivative contracts unless required by our bank loan.

We derive our revenue and cash flow principally from the sale of oil, natural gas, and NGLs. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas, and NGLs. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing. The market price for oil, natural gas, and NGLs is dictated by supply and demand; consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas, and NGLs. Index prices for oil, natural gas, and NGL’s are higher than in the recent past, however, prices may be volatile and, consequently, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production. In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 16,960 gross (10,640 net) acres, 96.5% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are focused. We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells. In Oklahoma we maintain an acreage position of approximately 47,120 gross (10,300 net) acres. Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 5,800 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 50 new horizontal wells based on an estimate of four wells per multi-section drilling unit, two in the Mississippian and two in the Woodford Shale. Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $34.6 million at an average 10% ownership level.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and availability of funds under our revolving credit facility.

District Information

The following table represents certain reserves and well information as of December 31, 2021.


Proved Reserves as of December 31, 2021 (MBoe)	Gulf Coast		Mid- Continent		West Texas		Other		Total
Developed		906		2,383		8,957		6		12,252
Undeveloped Total		—		—		—		—		—
Average Net Daily Production (Boe per day)		336		747		2,878		3		3,964
Gross Productive Wells (Working Interest and ORRI Wells)		207		549		576		200		1,532
Gross Productive Wells (Working Interest Only)		189		400		530		88		1,207
Net Productive Wells (Working Interest Only)		105		189		263		6		564
Gross Operated Productive Wells		137		195		321		—		653
Gross Operated Water Disposal, Injection and Supply wells		7		44		6		—		57

In several of our producing regions we have field service groups to service our operated wells and locations as well as third-party operators. These services consist of well service support, site preparation and construction services for drilling and workover operations. Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

Gulf Coast Region

Our activities in the Gulf Coast region are primarily production and development of our existing operated properties concentrated in east and southeast Texas. This region is managed from our office in Houston, Texas. Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet. As of December 31, 2021, we had 207 producing wells (105 net) in the Gulf Coast region, of which 137 wells are operated by us. The Average net daily production in our Gulf Coast Region in 2021 was 336 Boe. At December 31, 2021, we had 906 MBoe of proved reserves in the Gulf Coast region, which represented 7% of our total proved reserves. We maintain an acreage position of over 10,700 gross (3,215 net) acres in this region, primarily in Dimmit and Polk counties. We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, twenty-three water transport trucks, two saltwater disposal wells and several trucks and excavating equipment. Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations. The Company also owns, through its wholly-owned offshore company, a 60-mile-long pipeline on the shallow shelf of Texas that is currently idle but may someday have value. As of September 30, 2022, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region is managed from our office in Oklahoma City, Oklahoma. As of December 31, 2021, we had 549 producing wells (189 net) in the Mid-Continent area, of which 195 wells are operated by us. Principal producing intervals are in the Roberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet. Average net daily production in our Mid-Continent Region in 2021 was 747 Boe. On December 31, 2021, we had 2,383 MBoe of proved reserves in the Mid-Continent area, representing 20% of our total proved reserves. We maintain an acreage position of approximately 47,120 gross (10,300 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties. Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interests in several counties in the Stack and Scoop plays of Oklahoma where drilling primarily targets reservoirs of the Mississippian and Woodford formations.

In the first half of 2022, in the Mid-Continent region, the Company participated with 9.38% interest in the drilling of four horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc. All four wells have been completed and are online as of August 1st. The resulting production is an addition to our 2021 year-end proved producing reserve base. The Company divested of 354 non-strategic acres in Canadian County, year-to-date, with proceeds of $1.269 million.

West Texas Region

Our West Texas activities are concentrated in the Spraberry and Wolfcamp shale plays of the Permian Basin encompassing eight counties in West Texas. The oil produced from these shales is West Texas Intermediate Sweet and the gas is primarily casing-head gas with an average energy content of 1,400 Btu. The horizontal target depths range from 7,600 feet to 12,500 feet. This region is managed from our office in Midland, Texas.

As of December 31, 2021, we had 576 wells (263 net) in the West Texas area, of which 321 wells are operated by us. The average net daily production in Our West Texas Region in 2021 was 2,878 Boe. On December 31, 2021, we had 8,957 MBoe of proved reserves in the West Texas area, or 73% of our total proved reserves. We maintain an acreage position of approximately 16,960 gross (10,640 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties, and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals. We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck, and two roustabout trucks. Services, including well service support, site preparation, and construction services for drilling and workover operations, are provided to third-party operators as well as utilized for our operated wells and locations.

In the first half of 2022, the Company participated with 10.3% interest in the drilling of four 1.5-mile-long horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC. All four wells have been drilled and completed and began production in early August.

In the fourth quarter of 2022, the Company completed an acreage exchange agreement with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. In combination with existing acreage, this newly acquired acreage results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp formation and other prospective reservoirs through 2-mile-long horizontal laterals.

Along with the 1,200 contiguous acres created from the acreage exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the agreement, the Company has divested of a portion of its interest to operator for $16.1 million with the ability to acquire additional acreage from the operator located within the AMI. These exchanges should result in an approximately 50/50 ownership of the development with the operator. This newly formed 2,560 acreage-block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

In the fourth quarter of this year, we plan to participate with 20.8% interest in the drilling of five 2.5-mile-long horizontal wells in Martin County, Texas operated by ConocoPhillips, and to participate with 25% interest in the drilling of ten 2-mile-long horizontals in Reagan County, Texas with Hibernia Energy III, LLC. In the first quarter of 2023, BTA Oil Producers, LLC has indicated plans to drill nine 2.5-mile-long horizontals in Reagan County, Texas in which the Company will have an average 42 % interest. In addition, we plan to participate for 47% interest in two 3-mile-long horizontals with Apache Corporation in Upton County. In total, the Company will invest approximately $87 million in these 26 new wells with completions expected in the Spring of 2023 and all to be on production by mid-year 2023.

Reserve Information:

Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P. for each of the three years ended December 31, 2021. The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P. Report on Registrant’s Reserves Estimates. In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end reserves by our independent third-party engineers, Ryder Scott Company, L.P. The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and

twenty-five years of experience managing our reserves. Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist. See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows. All of our reserves are located within the continental United States. The following table summarizes our oil and gas reserves at each of the respective dates:


	Reserve Category
	Proved Developed								Proved Undeveloped								Total
As of December 31,	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf)		Total (MBoe)
2019		4,381		2,914		19,995		10,628		1,833		1,017		4,547		3,608		6,214		3,931		24,542		14,235
2020		2,684		2,258		13,633		7,214		1,784		787		3,897		3,221		4,468		3,045		17,530		10,435
2021		5,386		2,882		23,902		12,252		—		—		—		—		5,386		2,882		23,902		12,252

(a)	In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one barrel of natural gas liquids equals one barrel of oil.

In 2019, in West Texas, we participated in the initial three shallow horizontals on our Kashmir tract with one of each of these wells completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these wells and 5.3% in one well. All three wells were brought on production in May of 2019.

In 2020, in West Texas we participated in the drilling of seven wells: one for 8.6% interest which was brought into production in July of 2020, and six wells with an average 47.5% interest that were drilled but not completed at year-end and therefore classified as Proved Undeveloped in the year-end reserve report. The Company invested approximately $8.0 million in these seven wells in 2020. Also in 2020, proved producing reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest.

In 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end 2020. The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on our Slash, Osborn, and Leon tracts, with an average 1.34% interest. In addition, three wells drilled in Oklahoma in 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma, six wells designated as Shut-in on December 31, 2018, were brought into production in 2019: five located on our Ruthie tract, and one on our Braum tract.

In 2019, in our Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas: one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest. In 2020, the Company successfully recompleted one additional operated well in the Segno field with a 72.5% interest.

At December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by year-end 2020, and three that were not drilled until 2021. The three new horizontals along with the six uncompleted wells at year-end were brought online in late September and early October of 2021. These successful new wells are on our Kashmir tract in Upton County, Texas operated by Apache Corporation. These nine PUD wells at year-end 2020 accounted for 3,127 Mboe of the total undeveloped reserves where the Company has an average 47.5% interest and invested approximately $30 million dollars in these wells. The four other PUD wells, drilled but not completed at year-end 2020, are located in Grady County, Oklahoma and accounted for 95 Mboe of the total undeveloped reserves.

At December 31, 2021, the Company had 159 Mboe of proved developed shut-in reserves attributable to three horizontal wells drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online. Three of the four wells were successfully completed and online in January, 2022, while one well had completion issues and has been temporarily abandoned. Regarding the four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the paragraph above, reserves previously attributed to these wells were not included in the 2021 year-end reserve report as the operator has no near-term plans for their completion.

During 2022, in our West Texas horizontal drilling program, we participated with 10.3% interest in the drilling of four horizontal wells with SEM Operating Company and have received proposals for an additional 24 horizontal wells, 15 of those to begin in the fourth quarter of this year. In total, the Company is likely to invest approximately $75 million in these 28 wells. In Oklahoma, thus far in 2022, the Company is participating for 9.38% interest with Ovintiv Mid-Continent in the drilling of four wells on our Bohlman tract in Canadian County, Oklahoma. These four wells and the four SEM wells in West Texas were placed in production during August of this year. In the first quarter of 2023, we intent to participate with Apache in the drilling of two 3-mile-long horizontals in Upton County, Texas and with BTA Oil Producers in the drilling of nine 2.5 mile-long horizontals in Reagan County, Texas. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition. The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well-test data. The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves. Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area. These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2021, are summarized as follows (in thousands of dollars):


	Proved Developed				Proved Undeveloped				Total
As of December 31,	Future Net Revenue		Present Value 10 Of Future Net Revenue		Future Net Revenue		Present Value 10 Of Future Net Revenue		Future Net Revenue		Present Value 10 Of Future Net Revenue		Present Value 10 Of Future Income Taxes		Standardized Measure of Discounted Cash flow
2019	$	116,592	$	82,155	$	42,700	$	17,876	$	159,292	$	100,031	$	18,419	$	81,612
2020	$	43,886	$	34,717	$	37,346	$	21,823	$	81,232	$	56,539	$	14,920	$	41,619
2021	$	275,227	$	171,906	$	—	$	—	$	275,227	$	171,906	$	36,100	$	135,806

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%. Although this measure is not in accordance with U.S. generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure. We use this measure when assessing the potential return on investment related to oil and gas properties. The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow. A reconciliation of these values is presented in the last three columns of the table above. The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. “Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Our reserves include amounts attributable to non-controlling interests in the Partnerships. These interests represent less than 10% of our reserves.

In accordance with U.S. generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g. grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate. Also, in accordance with SEC specifications and U.S. generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case. Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.598 per MMBtu in 2021 as compared to $1.985 per MMBtu in 2020, and $2.581 per MMBtu in 2019. Through November 1, 2022, the twelve-month average of the first of the month Henry Hub index price is $6.166 per MMBtu. Oil prices, based on the NYMEX first of the month average price, were $66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and $55.69 per barrel in 2019. Through November 1, 2022, the NYMEX first of the month average price was $92.37. Since January 1, 2021, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. In 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our capital budget for the year is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

In the third quarter of 2021, nine two-mile horizontal wells in Upton County, Texas, operated by Apache Corporation, were completed and brought into production. In the fourth quarter of 2021, three two-mile horizontal wells operated by Ovintiv Mid-Continent in Canadian County, Oklahoma were completed and brought online in January 2022. The Company has an average of 47.5% interest in the nine wells completed with Apache and 11.25% interest in the three wells completed with Ovintiv.

In the second quarter of 2022, the Company participated with SEM Operating Company LLC in the drilling of four 7,900’ horizontal wells in Irion County, Texas with 10.3% interest. These four wells began their production in August. Also in the second quarter of 2022, the Company participated in the drilling of four 10,000’-long horizontal wells in Canadian County, Oklahoma with 9.38% interest. These four wells, operated by Ovintiv Mid-Continent, were also put into production in early August of this year. In the fourth quarter of this year another fifteen wells are planned to be spud.

Since the start of our West Texas horizontal drilling program in 2015, we have participated in 81 wells and invested approximately $130 million in horizontal drilling in the Permian Basin. This includes the four wells currently in progress with SEM Operating Company in Irion County, Texas.

In Upton County, Texas, we are developing a contiguous 3,260-acre block with our joint venture partner, Apache Corporation. In this block the Company has 2,600 leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed. In 2018, eight successful wells were drilled horizontally by Apache Corporation in the Wolfcamp “B” of this block with the Company participating for 49% interest and this is believed to be full development of the Wolfcamp “B” reservoir. Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block. These shallower reservoirs have been proven-up on our offset 1,300-acre Kashmir tract. It is expected that as many as 36 additional horizontals will be developed on this 3,260-acres in the near future. This development is estimated to cost approximately $387.0 million, with the Company’s share being approximately $174.4 million. Two 3-mile-long horizontals have been slated for the first quarter of 2023. In addition to the 36 prospective wells to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development. The potential of the Middle Spraberry on the 3,260-acre block is for 12 horizontal wells to be drilled and completed at a gross cost of approximately $138.0 million with the Company’s share being approximately $63.0 million. The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260-acre block being developed, as described above, the Company has also been developing an offsetting 1,300-acre block in Upton County, Texas, with Apache Corporation as operator. In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp: one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage. Prime holds 47.5% working interest in these reservoirs. As a result of the success of the initial three wells, nine additional horizontals followed and were completed in the third quarter of 2021. Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total. In addition to the Wolfcamp “A”, Jo Mill and Lower Spraberry, that are now considered fully developed on the tract, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $40.0 million with the Company’s share being approximately $18.8 million.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with ConocoPhillips in Martin County, Texas. In 2016 and 2017, four horizontal wells were drilled, completed, and put on production. The Company owns 35% to 38% interest in this joint venture acreage where we have the potential to drill as many as 36 additional wells.

As mentioned above, in West Texas, the Company participated for 10.3% interest with SEM Operating Company in four 7,900’-long horizontal wells in Irion County, Texas. We anticipate an investment of $2.55 million in these wells which have been producing since August. Also planned for this year is the drilling of ten 2-mile-long horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas and the drilling of five 2.5-mile-long horizontal wells with ConocoPhillips in Martin County. The Company intends to participate for approximately 25% interest in the ten wells with Hibernia and for 20.8% interest in five wells with Conoco Phillips. Our expected investment in the drilling and completion of these wells is $36.3 million.

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 5,800 net leasehold acres in the Scoop/Stack Play. In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts. In 2021, we participated for 11.25% interest with Ovintiv Mid-Continent Inc. in four wells on our Peters tract, in Canadian County. Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned. At today’s product prices, payout of the Company’s $2.3 million investment in these four wells occurred in four months.

In April 2022, in Oklahoma, the Company and Ovintiv Mid-Continent began drilling four horizontal wells on our Bohlman tract in the same area as the successful Peters wells. All four of the Bohlman wells have been drilled, completed, and were placed on production in early August.. The Company is participating with 9.38% interest in these wells with an approximate investment $2.45 million. In May, we sold 241 acres in Canadian County, Oklahoma for proceeds of $845,000, and in August another 113 acres for $423,700. Both of these sales were of non-strategic acreage and the Company retained its interest in existing wells and a small overriding royalty interest in future development.

We believe our 5,800 net leasehold acres in Oklahoma have the resource potential to support the drilling of as many as 50 new horizontal wells based on an estimate of four wells per multi-section drilling unit: two in the Mississippian and two in the Woodford Shale. Should we choose to participate in future development, our share of the capital expenditures would be approximately 34.6 million at a 10% ownership level; the Company will otherwise sell its rights for cash or cash plus a royalty or working interest.

LIQUIDITY AND CAPITAL RESOURCES

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy. For 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry. Our 2022 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility. As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest assets, or enter into strategic joint ventures.

Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage. Net cash provided by operating activities and proceeds from the sale of properties for the nine months ended September 30, 2022 was $47.3 million, compared to $18.8 million in the prior period.

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts. Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns. We sell the majority of our production at spot market prices. Accordingly, product price volatility will affect our cash flow from operations. To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.

Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly, the Company has in place the following swap agreements for oil and natural gas.


	2022		2023		2022	2023
Swap Agreements
Natural Gas (MMBTU)		279,000		254,000	$	$	3.60
Oil (barrels)		79,300		70,700	$	$	69.50

In the first quarter of 2022, the Company participated in the drilling of four wells with SEM Operating Company in Irion County, Texas for 10.3% interest and in April of this year began participating with Ovintiv Mid-Continent in four wells in Canadian County, Oklahoma with 9.38% interest.

These eight wells have been completed and were put on production in early August. In addition, the Company has received drilling proposals for an additional 26 horizontal wells to be drilled in West Texas with 15 of these slated to begin drilling this year. In total, the Company is likely to invest approximately $86 million in these 26 wells. Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $75 million. As of August 15, 2022, the Company has no outstanding borrowings under this line. The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves. The next borrowing base review is scheduled for December 2022. Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement. We are currently in compliance with these covenants and expect to be in compliance over the next twelve months. If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable. Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement. In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined borrowing base.

In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through three transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests.

In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for proceeds of $845,000 and a retained over-riding royalty interest.

In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.

In November of 2022, the Company completed an acreage exchange with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin. When combined with currently held acreage, this acreage exchange results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp and other prospective reservoirs through 2-mile-long horizontal laterals. In addition to this exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells. As part of the plan, the Company has divested a portion of its interest to the operator for $16.1 million and has the right to acquire additional acreage from the operator within the AMI. These exchanges should result in an approximate 50/50 ownership of the AMI development with the operator. This newly formed 2,560 acreage block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has a stock repurchase program in place, spending under this program during the first nine months of 2022 was $5.0 million. The Company expects continued spending under the stock repurchase program in 2022.

RESULTS OF OPERATIONS

2022 and 2021 Compared

We reported net income of $35.3 million, or $17.95 per share and $13.2 million, or $6.79 per share for the nine and three months ended September 30, 2022, respectively, as compared to net losses of $1.2 million, or $(0.58) per share and $5.0 million, or $(2.52) per share for the three and nine months ended September 30, 2021, respectively. Current year net income reflects increases in production and commodity price increases over the three and nine months ended September 30, 2022, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments. The significant components of income and expense are discussed below.

Oil, gas and NGLs sales increased $15.9 million, or 87.8% from $18.1 million for the three months ended September 30, 2021 to $34.0 million for the three months ended September 30, 2022, and $56.7 million, or 122.9% from $46.1 million for the nine months ended September 30, 2021 to $102.8 million for the nine months ended September 30, 2022

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2022 and 2021 (excluding realized gains and losses from derivatives).


			Nine months ended September 30,
	2022		2021		Increase / (Decrease)		Increase / (Decrease)
Barrels of Oil Produced		752,500		480,000		272,500		56.8	%
Average Price Received	$	100.39	$	63.28	$	37.11		58.6	%

Oil Revenue (In 000’s)	$	75,546	$	30,376	$	45,170.00		148.7	%


Mcf of Gas Sold		2,456,800		2,395,000		61,800		2.6	%
Average Price Received	$	6.01	$	3.32	$	2.69		81.0	%

Gas Revenue (In 000’s)	$	14,762	$	7,948	$	6,814.00		85.7	%


Barrels of Natural Gas Liquids Sold		332,400		298,000		34,400		11.5	%
Average Price Received	$	37.54	$	26.11	$	11.43		43.8	%

Natural Gas Liquids Revenue (In 000’s)	$	12,477	$	7,781	$	4,696		60.4	%


Total Oil & Gas Revenue (In 000’s)	$	102,785	$	46,105	$	56,680		122.9	%


			Three months ended September 30,
	2022		2021		Increase / (Decrease)			Increase / (Decrease)
Barrels of Oil Produced		244,500		152,000		92.500			60.9	%
Average Price Received	$	95.72	$	68.70	$	27.02			39.3	%

Oil Revenue (In 000’s)	$	23,403	$	10.442	$	12,961			124.1	%


Mcf of Gas Sold		879,800		950,000		(70,200	)		(7.39	)%
Average Price Received	$	7.23	$	4.21	$	3.02			71.7	%

Gas Revenue (In 000’s)	$	6,359	$	3,998	$	2,361			59.1	%


Barrels of Natural Gas Liquids Sold		122,400		103,000		19,400			18.8	%
Average Price Received	$	34.35	$	35.26	$	(0.91	)		(2.59	)%

Natural Gas Liquids Revenue (In 000’s)	$	4,204	$	3,632	$	572			15.7	%


Total Oil & Gas Revenue (In 000’s)	$	33,966	$	18,072	$	15,894			87.9	%

Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues.

Field service income increased $1.4 million or 58.3% from $2.4 million for the third quarter 2021 to $3.8 million for the third quarter 2022 and increased $4.6 million, or 74.2% from $6.2 million for the nine months ended September 30, 2021 to $10.8 million for the nine months ended September 30, 2022. These changes reflect the increase in utilization and rates resulting from the oil and gas price increases during these periods. Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expense increased $2.3 million or 35.9% from $6.4 million for the third quarter 2021 to $8.7 million for the third quarter 2022 and increased $11.3 million or 73.9% from $15.3 million for the nine months ended September 30, 2021 to $26.6 million for the nine months ended September 30, 2022. This increase is primarily due to higher production taxes related to higher commodity prices during 2022 combined with workover expenses and lease operating expense related to higher lifting cost properties returned to production as commodity prices increased.

Field service expense increased $0.1 million or 3.4% from $2.9 million for the third quarter 2021 to $3.0 million for the third quarter 2022 and increased $3.3 million, or 53.2% from $6.2 million for the nine months ended September 30, 2021 to $9.5 million for the nine months ended September 30, 2022. Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and nine months ended September 30, 2022 compared with the same periods of 2021. These changes reflect the increase in utilization resulting from the oil and gas price increases during these periods.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.8 million, or 11.6% from $6.9 million for the third quarter 2021 to $7.7 million for the third quarter 2022 and $1.9 million, or 9.5% from $20.0 million for the nine months ended September 30, 2021 to $21.9 million for the nine months ended September 30, 2022. These increases reflect the change in the property basis combined with production increases in 2022.

General and administrative expense increased $5.3 million, or 85.5% from $6.2 million for the nine months ended September 30, 2021 to $11.5 million for the nine months ended September 30, 2022, and increased $0.5 million, or 25.0% from $2.0 million for the three months ended September 30, 2021 to $2.5 million for the three months ended September 30, 2022. This increase in 2022 is primarily due to increased employee compensation and benefits.

Interest expense decreased from $0.5 million for the third quarter 2021 to $0.3 million for the third quarter 2022 and from $1.5 million for the nine months ended September 30, 2021 to $0.8 million for the nine months ended September 30, 2022. This decrease reflects the increase in rates and reduced borrowings under our revolving credit agreement.

Income tax benefit/expense for the September 30, 2022 and 2021 periods varied due to the change in net income or loss for those periods.

Item 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Company is a smaller reporting company and no response is required pursuant to this Item.

Item 4.

CONTROLS AND PROCEDURES

As of the end of the current reported period covered by this report, the Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of the Company’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934 (the “Exchange Act”). Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective with respect to the recording, processing, summarizing and reporting, within the time periods specified in the Commission’s rules and forms, of information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act.

There were no changes in the Company’s internal control over financial reporting that occurred during the first nine months of 2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1.

LEGAL PROCEEDINGS

None.

Item 1A.

RISK FACTORS

The Company is a smaller reporting company and no response is required pursuant to this Item.

Item 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

There were no sales of equity securities by the Company during the period covered by this report.

During the nine months ended September 30, 2022, the Company purchased the following shares of common stock as treasury shares.


2022 Month	Number of Shares		Average Price Paid per share		Maximum Number of Shares that May Yet Be Purchased Under The Program at Month—End (1)
January		2,981	$	76.21		144,740
February		5,948	$	73.26		138,792
March		2,259	$	75.36		136,533
April		3,426	$	74.82		133,107
May		5,963	$	82.37		127,144
June		18,855	$	85.18		108,289
July		15,645	$	79.68		92,644
August		5,500	$	87.99		87,144
September		800	$	92.80		86,344

Total/Average		61,377	$	81,33

(1)

In December 1993, we announced that the Board of Directors authorized a stock repurchase program whereby we may purchase outstanding shares of the common stock from time-to-time, in open market transactions or negotiated sales. On October 31, 2012 and June 13, 2018, the Board of Directors of the Company approved an additional 500,000 and 200,000 shares respectively, of the Company’s stock to be included in the stock repurchase program. A total of 3,700,000 shares have been authorized, to date, under this program. Through September 30, 2022, a total of 3,615,756 shares have been repurchased under this program for $78,266,619 at an average price of $22,15 per share. Additional purchases of shares may occur as market conditions warrant. We expect future purchases will be funded with internally generated cash flow or from working capital.

Item 3.

DEFAULTS UPON SENIOR SECURITIES

None

Item 4.

RESERVED

Item 5.

OTHER INFORMATION

Non

Item 6.

EXHIBITS

The following exhibits are filed as a part of this report:


Exhibit No.

3.1		Certificate of Incorporation of PrimeEnergy Resources Corporation, as amended and restated of December 21, 2018, (filed as Exhibit 3.1 of PrimeEnergy Resources Corporation Form 8-K on December 27, 2018, and incorporated herein by reference).

3.2		Bylaws of PrimeEnergy Resources Corporation as amended and restated as of April 24, 2020 (filed as Exhibit 3.2 of PrimeEnergy Resources Corporation Form 8-K on April 27, 2020 and incorporated herein by reference).

10.18		Composite copy of Non-Statutory Option Agreements (Incorporated by reference to Exhibit 10.18 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2004).

10.22.6		FOURTH AMENDED AND RESTATED CREDIT AGREEMENT dated as of July 5, 2022, is among PRIMEENERGY RESOURCES CORPORATION, a Delaware corporation (the “Borrower”), each of the Lenders from time to time party hereto and CITIBANK, N.A. (in its individual capacity, “Citibank”), as administrative agent for the Lenders (in such capacity, together with its successors in such capacity, the “Administrative Agent”) (filed as exhibit 10.22.6 of PrimeEnergy Resources Corporation Form 10-Q for the Quarter Ended June 30 2022, and incorporated by reference).

14		PrimeEnergy Resources Corporation Code of Business Conduct and Ethics, as amended December 16, 2011 (Incorporated by reference to Exhibit 14 of PrimeEnergy Resources Corporation Form 10-K for the year ended December 31, 2011).

31.1		Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

31.2		Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)/15d-14(a) of the Securities Exchange Act of 1934, as amended (filed herewith).

32.1		Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

32.2		Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herewith).

101.INS		Inline XBRL (eXtensible Business Reporting Language) Instance Document (filed herewith)

101.SCH		Inline XBRL Taxonomy Extension Schema Document (filed herewith)

101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase Document (filed herewith)

101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase Document (filed herewith)

101.LAB		Inline XBRL Taxonomy Extension Label Linkbase Document (filed herewith)

101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase Document (filed herewith)

104		Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.